Awl Bidness

[trysail]

http://www.bloomberg.com/news/2013-...ure-locked-in-ice-beneath-seabeds-energy.html




Asians Hunt Gas Treasure Locked in Ice Beneath Seabeds
By Rakteem Katakey and Tsuyoshi Inajima
March 13, 2013

Japan and India, Asia’s biggest energy consumers after China, are closer to unlocking natural gas deposits trapped in ice below the seabed that may prove bigger than the world’s known fossil-fuel reserves.

Japan Oil, Gas & Metals National Corp. said yesterday it produced gas in the world’s first offshore test to extract the fuel from the frozen depths. A team including Oil & Natural Gas Corp., India’s biggest energy explorer, will drill off the east coast this year and try to produce the fuel, according to two officials at the regulator Directorate General of Hydrocarbons. They asked to not be named before the official announcement.

The nations are trying to catch up with North America, where discoveries of gas in shale rock and tar sands herald an energy revolution carrying the U.S. and Canada toward energy independence. While shale is found in only certain parts of the globe, carbon frozen with water -- called methane hydrates or burnable ice -- is found under most sea beds. The catch: There’s no technology yet to commercially extract that gas.

“Methane hydrates are everywhere, including in some of the fastest-growing economies,” said Will Pearson, director for global energy & natural resources at Eurasia Group in London. “If the technology is developed, it’ll alter the gas market. What is already the golden age of gas will last much longer.”

Natural gas, the fuel burned to make heat and electricity, is predominantly methane. A methane hydrate is a crystal of methane molecules surrounded by a cage of water molecules, according to the U.S. Geological Survey.

Methane hydrates, stable under low temperatures and high pressure, can disintegrate when removed from those conditions.

Double Size
Initial estimates suggest carbon deposits in hydrates are double the size of all known oil, gas and coal reserves, the U.S. Geological Survey said in a January 2013 report. The world’s proven reserves of natural gas alone were 208.4 trillion cubic meters at the end of 2011, according to BP Plc. (BP/)

Gas molecules locked in ice have also been found in the North American permafrost and the Gulf of Mexico.

India is drilling for frozen gas it has preliminarily estimated to be as large as 1,894 trillion cubic meters, according to the website of the Directorate General of Hydrocarbons, the oil and gas exploration and production regulator. Japan’s deposits of frozen gas may be large enough to supply its needs for about 100 years, according to Japan Oil, Gas & Minerals, a government-affiliate known as JOGMEC.

‘More Independence’
“Methane hydrate could give Japan its own energy source and more independence,” said Tomoo Suzuki, professor emeritus at Tokyo Institute of Technology, who leads a study on methane hydrate deposits off the coast of Kochi prefecture. “The question is whether extracting gas from methane hydrate can be economically viable.”

Japan Drilling Co., which signed a contract to drill wells for the test project last year, climbed 3.9 percent to 6,730 yen in Tokyo trading today, extending yesterday’s 18 percent gain. Japan Petroleum Exploration Co., the operator of the offshore project, declined 4.8 percent to 3,975 yen after rising 5.7 percent yesterday.

India, which discovered methane hydrates in the Bay of Bengal off its east coast, will later this year drill a few wells and engage in some test production to determine the size of the resource, a person familiar with the program said. Scientists have also found traces of conventional gas under the layer of hydrates on the ocean floor, the person said.

Oil & Natural Gas Chairman Sudhir Vasudeva didn’t answer calls to his telephone seeking comment on the company’s plan to extract methane from hydrates.

Test Phase
In Japan’s test phase, gas was produced in the Nankai Trough about 50 kilometers (31 miles) off the coast of the country’s main Honshu island, JOGMEC said.

The Eastern Nankai Trough deposits may hold the equivalent of about 40 trillion cubic feet of methane, a primary element of natural gas, according to the statement. That’s equivalent to about 11 years of Japan’s LNG imports, it said.

The country is trying to to enable commercial use by fiscal 2018, according to JOGMEC. Japan used a depressurization method in its latest test, a technology that was used when Japan and Canada jointly conducted a test production in the permafrost of northern Canada in 2008. That was the world’s first continuous and stable production from frozen gas sediments, according to the company.

Production Cost
The success of the offshore test doesn’t guarantee commercialization because of the short time span of production, said Yuji Morita, a senior researcher at Japan’s Institute of Energy Economics. The production cost won’t be an issue in the run-up to the commercialization of the fuel, Morita said.

“Hydrates store immense amounts of methane, with major implications for energy resources and climate, but the natural controls on hydrates and their impacts on the environment are very poorly understood,” the U.S. Geological Survey said in its January report. “Extraction of methane from hydrates could provide an enormous energy and petroleum feedstock resource.”

Explorers must find a way to avoid releasing large quantities of methane from hydrates into the air and the ocean. Methane traps heat so effectively it is about 10 times more potent than carbon dioxide as a greenhouse gas, according to the agency. Ice melts can reduce the pressure on the hydrates, resulting in the gas leaking out.

A study in the journal Nature in December 2011 found thawing of permafrost may release the equivalent of 380 billion tons of carbon dioxide this century if the Arctic warms by 7.5 degrees Celsius (13.5 degrees Fahrenheit). That includes large quantities of methane, which may increase temperatures.

New Sources
Nations around the world are seeking new energy sources as demand increases. China, the world’s biggest energy consumer, is looking for technology to produce from the world’s biggest estimated shale gas deposit and enhance output from coal seams.

While India imports more than 75 percent of its crude oil and a quarter of its natural gas requirements, Japan buys all its oil and gas from overseas and is seeking to find ways to cut its dependence on Middle Eastern crude oil.

“Countries that highlight the opportunity are those with limited oil and gas production,” said Nathan Piper, an Edinburgh-based analyst at RBC Capital Markets. “Gas hydrates remain challenging due in part to the offshore location.”




http://www.bloomberg.com/news/2013-...ure-locked-in-ice-beneath-seabeds-energy.html

 

[trysail]

It's official. Rosneft is now the world's largest (yep, bigger than ExxonMobil, bigger than Shell, bigger than PetroChina) publicly-traded hydrocarbon company.



__________________

http://www.bloomberg.com/news/2013-...llion-acquisition-of-oil-producer-tnk-bp.html



Rosneft Completes $55 Billion Acquisition of TNK-BP
By Anna Shiryaevskaya
March 21, 2013

OAO Rosneft, Russia’s biggest oil company, sealed its $55 billion acquisition of TNK-BP, becoming the world’s largest publicly traded oil producer by output.

Rosneft completed the transaction today, the state-run producer said in a statement. The deal gives BP Plc (BP/) $16.7 billion in cash and 12.8 percent of Rosneft stock for its half of TNK-BP, Russia’s third-largest oil producer. Rosneft also paid $27.7 billion in cash to AAR, which represents the group of billionaires holding the other half.

“We welcome BP as the major shareholder of Rosneft, which will take part in shaping the company’s strategy,” Igor Sechin, Rosneft chief executive officer and a long-time ally of President Vladimir Putin, said in the statement.

The biggest takeover in Russian history strengthens the state’s hold over oil and gas production, the source of about half of government revenue. Moscow-based Rosneft, which was partly built on the state-enforced bankruptcy of Yukos Oil Corp., will pump more than 4 million barrels of crude a day, exceeding the output of Canada or Iraq.

After recycling $4.9 billion of cash from the deal into Rosneft stock, BP has become the second-largest shareholder after the Russian state with a 19.8 percent holding and CEO Bob Dudley will sit on the board. The U.K. company will be able to include its share of Rosneft’s reserves and production in its own accounts.

The London-based producer bought the additional 5.7 percent in Rosneft from state holding Rosneftegaz.

‘Wonderful Opportunity’
The deal gives BP “a wonderful opportunity to forge a new partnership with a great Russian oil company,” Dudley, who is also a member of Rosneft’s steering committee on the integration of TNK-BP, said in the statement.

Rosneft rose as much as 2.1 percent in Moscow, the most since Feb. 13, to trade at 242.07 rubles as of 5:55 p.m. local time. BP fell 0.3 percent to 446.65 pence in London.

BP and Rosneft will consider opportunities for joint work on “standalone projects, both in Russia and internationally,” according to the statement.

TNK-BP, which accounted for about a quarter of BP’s output and a fifth of its reserves, paid the company $19 billion in dividends since it was formed in 2003. BP’s initial investment in the venture was $8 billion.

Today’s deal will see Rosneft, which has a market value of $83 billion, overtake PetroChina Co., Asia’s largest oil company, in crude oil production.

Putin met with Dudley and Sechin in his residence outside Moscow, congratulating the executives on the deal’s completion, Interfax reported.

The sale of the stake in TNK-BP gives Alfa, Access and Renova, the shareholders of the AAR group, an opportunity “to capitalize on major new opportunities in Russia and around the world,” according to an e-mailed statement.



http://www.bloomberg.com/news/2013-...llion-acquisition-of-oil-producer-tnk-bp.html

 

[trysail]

http://www.bloomberg.com/news/2013-...arctic-oil-rush-as-energy-giants-embrace.html



Russia Lets China Into Arctic Rush as Energy Giants Embrace
By Rakteem Katakey and Will Kennedy
March 25, 2013

Russia’s decision to give China a share of prized Arctic exploration licenses as part of a “breakthrough” deal signals how the world’s largest oil and gas producer and the biggest energy consumer are redrawing the global energy map.

Under agreements signed during President Xi Jinping’s first state trip abroad, China may double oil imports from state-run OAO Rosneft to more than 620,000 barrels a day, challenging Germany as the biggest buyer of Russian crude. The two also plan to sign an agreement this year to build a pipeline to ship Russian gas to China.

In return, China National Petroleum Corp. (CNPZ) will join with Rosneft in exploring three offshore Arctic areas for oil, the first such deal Russia has signed with an Asian company. The ocean north of Russia is considered one of the world’s largest unexplored oil provinces, and Exxon Mobil Corp., Italy’s Eni SpA and Norway’s Statoil ASA have already agreed to help finance drilling.

“China is emerging as the most important buyer of Russian oil and gas, helping Russian companies diverge from European exports,” said Tony Regan, an energy consultant with Tri-Zen International Inc. in Singapore, which counts Royal Dutch Shell Plc and OAO Lukoil as clients. “It’s also a huge catalyst for Russian companies to develop their oil and gas fields.”

Well Spent
Rosneft, the biggest traded oil producer by output, will borrow $2 billion from China Development Bank Corp., backed by 25 years of oil supplies, under accords signed March 22 in the Kremlin. OAO Gazprom said it plans to conclude a 30-year gas- supply contract to China by the end of the year.

“We didn’t come here and waste our time,” Xi said through a Russian translator at the Kremlin ceremony, and called the accords a “breakthrough.”

Rosneft will boost oil supplies to China by 800,000 metric tons this year, Chief Executive Officer Igor Sechin said after signing an agreement with CNPC counterpart Zhou Jiping.

Annual exports may later climb to as much as 31 million tons, or 620,000 barrels a day, from 15 million tons, he said. Rosneft raising China exports to 50 million tons of oil a year “isn’t unattainable,” Sechin said in an interview broadcast on national television channel Rossiya 24.

Rosneft rose 2.3 percent to 243.3 rubles as of 4:06 p.m. in Moscow, the biggest gain since Feb. 13. CNPC’s listed unit, PetroChina Co., dropped 1 percent in Hong Kong.

‘More Aggressive’
Germany was the biggest customer of Russian crude in 2011, buying about 700,000 barrels a day, according to the U.S. Energy Information Administration. China ranked fourth behind the Netherlands and Poland.

The deal with CNPC to drill in three areas of the Pechora and Barents Seas is another example of the growing clout of China’s biggest oil company, which was also offered eight onshore blocks in Russia.

Earlier this month, CNPC agreed to buy a $4.2 billion stake in gas fields off Mozambique from Eni, a deal that will make it a partner in the world’s second-largest gas export terminal.

“CNPC is becoming a prime player outside China and they’re likely to get more aggressive in acquiring oil and gas assets around the world,” said Sonia Song, a Hong Kong-based analyst at Nomura Holdings Inc.

CNPC’s PetroChina will raise overseas output to 60 percent of its total in the next eight years.

Overseas Drive
The explorer and refiner plans to invest at least $60 billion this decade in energy assets stretching from the Middle East and Central Asia to the Americas and Asia-Pacific, Vice President Sun Longde said March 21 after the company reported a 13 percent drop in net income last year. The drive overseas is to help counter losses at home from state price controls on gas and other fuels.

Gazprom, Russia’s natural-gas export monopoly, signed a memorandum with CNPC on building a pipeline along the so-called eastern route with shipments of 38 billion cubic meters a year, starting in 2018, CEO Alexei Miller told reporters in the Kremlin. Gas deliveries may rise to 60 billion cubic meters.

The deal, which has been under discussion for more than 10 years, may include advance payments from China, Miller said. Gazprom and CNPC plan to set legally binding terms for supplies in June and sign a deal by the end of this year, he said.

“Diversifying export markets has long been on the agenda” for Gazprom...If pricing can be decided, this could “mark the beginning of one of the largest supply agreements in a decade.”



http://www.bloomberg.com/news/2013-...arctic-oil-rush-as-energy-giants-embrace.html

 

[trysail]

http://finance.yahoo.com/news/la-man-gets-prison-plot-165736753.html



La. man gets prison for plot to defraud BP

Covington businessman gets 18 months in prison for defrauding BP out of $1.4M after Gulf spill
By Michael Kunzelman

NEW ORLEANS (AP) -- A businessman was sentenced Wednesday to 18 months in prison for a plot in which he fraudulently billed BP for roughly $1.4 million for use of a helicopter after the company's massive 2010 oil spill in the Gulf of Mexico.

Bay Ingram, who owned Southeast Recovery Group, had faced a maximum of five years in prison following his guilty plea last year to a conspiracy charge. U.S. District Judge Sarah Vance imposed his prison sentence and also ordered the Covington man to pay a total of $463,271 in restitution to BP and Rotorcraft Leasing Company, which provided Ingram with the helicopter and its crew.

Ingram, 50, billed BP for a helicopter that the St. Bernard Parish Sheriff's Office and Louisiana Department of Wildlife and Fisheries were supposed to use after the spill. Prosecutors say he falsified and forged documents to justify inflated invoices he submitted to the London-based oil giant in the aftermath of the Deepwater Horizon rig explosion, which killed 11 workers and triggered the nation's worst offshore oil spill.

Ingram also is accused of billing BP more than $300,000 for the construction of five helipads that only cost around $110,000.

Ingram told Vance that he has always tried to live his life as a "law-abiding citizen."

"I take full and complete responsibility for my actions," he said. "Whatever you decide, I'll accept. And I'll do it with grace, and I'll do it with character."

In August 2010, BP paid Ingram roughly $113,000 for the use of the helicopter. But the company refused to pay subsequent invoices that he submitted without securing the proper authorization or approval for continued use of the chopper.

Ingram tried to convince BP to pay the other invoices by presenting it with a forged contract and altered flight logs, according to a court filing. He also tried to dupe his suppliers, including Rotarcraft Leasing, into believing they would be paid by sending them emails under the name of a fictitious person purporting to be an auditor for a BP contractor, prosecutors say.

Ingram already has paid full restitution of $149,179 to BP and $314,091 to Rotarcraft Leasing, said his attorney, Pat Fanning.

Assistant U.S. Attorney Matt Chester said Rotarcraft Leasing is a small company that was "teetering on the edge of failure" as a result of Ingram's scheme. BP also was a victim of the crime even though it balked at paying the additional $1.4 million that Ingram had billed for the helicopter.

"BP was trying to do the right thing," Chester said. "It certainly did not need to be taken advantage of."

Federal sentencing guidelines called for a prison term ranging from two years to 30 months, but Vance agreed to give Ingram a more lenient sentence. She cited his lack of criminal record and history of "many charitable acts and good works," including paying the tax bill for an elderly couple who lost their home and paying the private-school tuition for a friend's son.

"Most of these acts were done anonymously," Vance said.

Chester said Ingram deserved a sentence that fell within the guidelines. His success as a businessman and financial resources shouldn't be grounds for leniency, the prosecutor argued.

"If anything, it weighs in favor of the opposite," Chester added.

Ingram is scheduled to report to prison on June 3. His sentencing hearing was held down the hall from the courtroom where a different judge is presiding over a civil trial over the Deepwater Horizon disaster.



http://finance.yahoo.com/news/la-man-gets-prison-plot-165736753.html

 

[trysail]

One person with clearly thought-through ideas about what to do was Vagit Alekperov. Born in Baku, he had worked in the offshore Azerbaijani oil industry until transferring at age twenty-nine to the new heartland of Soviet oil, West Siberia. There he came to the attention of Valery Graifer, then leading West Siberia to its maximum performance. Recognizing Alekperov's capabilities, Graifer promoted him to run one of the most important frontier regions in West Siberia. In 1990, Alekperov leapfrogged to Moscow, where he became deputy oil minister.

On trips to the West, Alekperov visited a number of petroleum companies. He saw dramatically different ways of operating an oil business. "It was a revelation," he said. "Here was a type of organization that was flexible and capable, a company that was tackling all the issues at the same time— exploration, production, and engineering— and everybody pursuing the common goal, and not each branch operating separately." He came back to Moscow convinced that the typical organization found in the rest of the world— vertically integrated companies with exploration and production, refining and marketing all in one company— was the way to organize a modern oil industry...

This restructuring would have been hard to do under any circumstances. It was very hard to do in the early and mid-1990s, when the state was very weak and law and order was in short supply. There was violence at every level, as Russian mafyias— gangs, scarily tattooed veterans of prison camps and petty criminals— ran protection rackets, stole crude oil and refined products, and sought to steal assets from local distribution terminals...

Meanwhile, following on Yeltsin's privatization decree, the Russian oil majors were beginning to take shape.

The most visible was LUKoil. Vagit Alekperov, equipped with a clear vision of an integrated oil company, set about building it as quickly as possible. The first thing was to pull together a host of disparate oil production organizations and refineries that had heretofore had no connection. He barnstormed around the country trying to persuade the managements of each organization to join this unfamilar entity called LUKoil. In order for LUKoil to come into existence, every single entity had to sign on. "The hardest thing was to convince the managers to unite their interests," said Alekperov. "There was chaos in the country, and we all had to survive, we had to pay wages, and keep the entities together. Without uniting, we would not be able to survive." They heard the message, all signed on, and LUKoil became a real company...

****​

At the military academy, he imbibed the careers of other ambitious young officers from modest circumstances— Ghaddaffi in Libya, Juan Velasco Alcarado in Peru— who had gone on to seize power.

It was in 1992... that Chavez and his co-conspirators launched their failed coup. In the subsequent two years that followed his arrest, Chavez spent his time in prison reading, writing, debating, imagining his victory, receiving a continuing stream of visitors who would be important to his cause— and basking in his new glory as a national celebrity...

​

-Daniel Yergin
The Quest: Energy, Security and The Remaking of The Modern World
New York, N.Y. 2011.





It's fascinating stuff. From its earliest days, the energy business has been a global activity full of bigger-than-life characters.

In a sequel to his 1991 Pulitzer Prize-winning, best-seller The Prize, Yergin details events of the last twenty years and describes some of the more recent heroes and villains.





You should check him out. Alekperov is the real deal.

ht tp://www.bloomberg.com/news/2013-02-06/lukoil-billionaire-alekperov-instructs-son-not-to-sell-his-stake.html

<blockquote>One person with clearly thought-through ideas about what to do was Vagit Alekperov. Born in Baku, he had worked in the offshore Azerbaijani oil industry until transferring at age twenty-nine to the new heartland of Soviet oil, West Siberia. There he came to the attention of Valery Graifer, then leading West Siberia to its maximum performance. Recognizing Alekperov's capabilities, Graifer promoted him to run one of the most important frontier regions in West Siberia. In 1990, Alekperov leapfrogged to Moscow, where he became deputy oil minister.

On trips to the West, Alekperov visited a number of petroleum companies. He saw dramatically different ways of operating an oil business. "It was a revelation," he said. "Here was a type of organization that was flexible and capable, a company that was tackling all the issues at the same time— exploration, production, and engineering— and everybody pursuing the common goal, and not each branch operating separately." He came back to Moscow convinced that the typical organization found in the rest of the world— vertically integrated companies with exploration and production, refining and marketing all in one company— was the way to organize a modern oil industry...

This restructuring would have been hard to do under any circumstances. It was very hard to do in the early and mid-1990s, when the state was very weak and law and order was in short supply. There was violence at every level, as Russian mafyias— gangs, scarily tattooed veterans of prison camps and petty criminals— ran protection rackets, stole crude oil and refined products, and sought to steal assets from local distribution terminals...

Meanwhile, following on Yeltsin's privatization decree, the Russian oil majors were beginning to take shape.

The most visible was LUKoil. Vagit Alekperov, equipped with a clear vision of an integrated oil company, set about building it as quickly as possible. The first thing was to pull together a host of disparate oil production organizations and refineries that had heretofore had no connection. He barnstormed around the country trying to persuade the managements of each organization to join this unfamilar entity called LUKoil. In order for LUKoil to come into existence, every single entity had to sign on. "The hardest thing was to convince the managers to unite their interests," said Alekperov. "There was chaos in the country, and we all had to survive, we had to pay wages, and keep the entities together. Without uniting, we would not be able to survive." They heard the message, all signed on, and LUKoil became a real company...

-Daniel Yergin
<u>The Quest: Energy, Security and The Remaking of The Modern World</u>
New York, N.Y. 2011.</blockquote>

<blockquote>

OAO Lukoil’s billionaire Chief Executive Officer Vagit Alekperov, who owns about a fifth of the Russian oil producer, arranged for his son Yusuf to maintain his holding beyond his death.

“I’ve already arranged for my stake, even if I leave this life, to be indivisible to secure the company’s stability for many years ahead,” Alekperov said in an interview on Ekho Moskvy radio late yesterday. “My son won’t have the right to split and sell it.”

Alekperov, 62, owns more than 20 percent of Lukoil, Russia’s second-largest oil producer and the country’s biggest non-state energy company. His son Yusuf, a graduate of Gubkin Russian State University of Oil and Gas, works at oilfields in western Siberia as a technologist, according to the CEO.

“He must follow that path and see how people work at fields,” Alekperov said, adding that he isn’t preparing Yusuf to replace him. “Let him choose his fate for himself.”

</blockquote>

 

[trysail]

http://www.bloomberg.com/news/2013-...anifa-oil-field-ahead-of-plan.html?cmpid=yhoo



Saudi Aramco Starts Pumping From Manifa Oil Field Ahead of Plan
By Wael Mahdi
April 15, 2013

Saudi Arabian Oil Co. started producing crude from Manifa, the world’s fifth-largest oil field, on April 10, three months ahead schedule.

Saudi Aramco, as the state-owned producer is known, said today the field will produce 500,000 barrels a day of Arabian heavy crude by July and it will reach 900,000 barrels a day by end of next year.

Crude supply from the $17-billion Manifa project will help the company to maintain its maximum production capacity of 12 million barrels day, without raising output beyond that level, Aramco said in an e-mailed statement.

Manifa is the last of the so-called giant oil field discoveries in Saudi Arabia to begin operations. Its output will feed the Satorp refinery and two other facilities currently under construction, Jazan and Yasref. The International Energy Agency forecast in July that capacity in the kingdom, the world’s biggest crude exporter, will fall this year before rebounding in 2014 once Manifa starts production.

Aramco will invest more than $35 billion in exploration and development in the next five years to keep its oil production portfolio robust, Chief Executive Officer Khalid Al-Falih said in a speech posted on the company’s website in September.

The Satorp refinery in Jubail, a joint venture with France’s Total SA, will take its first crude next month, Chief Executive Officer Christophe de Margerie said April 11 in Paris. Yasref in Yanbu, which Aramco is building with China Petroleum & Chemical Corp., or Sinopec, and Jazan will each be able to process 400,000 barrels a day of crude.



http://www.bloomberg.com/news/2013-...anifa-oil-field-ahead-of-plan.html?cmpid=yhoo

 

[trysail]

http://www.bloomberg.com/news/2013-...d-by-crude-drop-as-spending-soars-energy.html




Oil’s Big Five Squeezed by Crude Drop as Spending Soars
By Brian Swint
April 24, 2013

The biggest oil companies are failing to increase earnings as crude trades near a nine-month low, production wanes and costs rise.

For only the second time since 2009, Royal Dutch Shell Plc, Exxon Mobil Corp., Chevron Corp., BP Plc and Total SA will all report lower quarterly profit when they announce earnings in the coming week, analysts’ estimates show. The group, which is investing a record $155 billion this year to bolster output, is disappointing investors: the companies’ shares have gained an average 2 percent this year as the Standard & Poor’s 500 Index jumped 11 percent...

...Benchmark Brent crude, used to price two-thirds of global sales, has dropped 9 percent this year to $101 a barrel as fracking technology opens wells in the U.S., prompting BP to predict the nation may top Saudi Arabia as the biggest producer of oil and liquid fuels...

At the same time, producing oil and natural gas is becoming harder for the world’s largest energy companies. Output at the five so-called supermajors reached its zenith in 2004 at 16.9 million barrels a day of oil equivalent. Production has slipped 7 percent since then to 15.7 million barrels last year...

Capital Intensity
“The recent fall in oil prices is hardly likely to change sentiment toward this group of companies, whilst capital intensity has continued to rise as industry inflation continues. The global majors have as a group been a poor investment for some time.”

The U.S. will surpass Russia and Saudi Arabia this year to become the largest liquid fuel producer, BP said Jan 16. Liquids output, which includes oil, natural gas liquids and biofuels, will be boosted in the U.S. by tight oil extracted by the same technology that sparked a boom in shale gas.

The quest for new deposits to replace shrinking established fields is costing a record amount this year and all five companies have pledged to maintain or increase capital expenditure to bolster output. BP Chief Executive Officer Bob Dudley said in February that the inflation rate for oilfield services and supplies is running at about 10 percent a year...



more...

http://www.bloomberg.com/news/2013-...d-by-crude-drop-as-spending-soars-energy.html

 

[JohnnySavage]

my new favorite show.

 

[trysail]

my new favorite show.

That's enough to make anybody believe that money spent on geology, geophysics and seismic work is money well spent.


A little well control goes a long way.




P.S., LOL.
See: Sid Richardson, George Getty, Glenn McCarthy, Clint Murchison, etc.

 

[thør]

my new favorite show.

A couple of years ago, a friend of mine was drilling a gas well on the KY/TN border and they hit oil. What a PITA that turned into.

 

[trysail]

my new favorite show.

Those folk need Jed Clampett.

 

[trysail]

http://www.bloomberg.com/news/2013-...capacity-will-rise-to-15-million-barrels.html



Saudi Prince Says Crude Capacity Will Rise to 15 Million Barrels
By Anthony DiPaola and Wael Mahdi
April 30, 2013

Saudi Arabia plans to raise production capacity to 15 million barrels a day by 2020 from 12.5 million barrels a day now, a Saudi prince said, reviving talk of a higher internal target.

The new capacity will allow the kingdom to be able to export as much as 10 million barrels of crude a day, Prince Turki Al Faisal, 68, a former head of intelligence, said in an April 25 speech at Harvard University that was posted on the university’s website yesterday.

Saudi Arabia’s oil minister Ali al-Naimi told reporters in March last year that the kingdom doesn’t plan to boost capacity beyond 12.5 million barrels a day, though it has the ability to do so if needed. The country first announced its plans to raise daily capacity to 15 million barrels in a speech delivered by al-Naimi in 2008, weeks before Brent crude reached a record $147 a barrel as OPEC’s spare capacity shrank.

The desert kingdom maintains the largest portion of spare capacity within the Organization of Petroleum Exporting Countries, producing about 9 million barrels a day last month, and keeping 3.5 million barrels a day unused.

Khalid Al-Falih, chief executive officer of Saudi Arabian Oil Co., or Saudi Aramco, said in November 2011 that the state- run company had no plans to increase daily capacity beyond 12.5 million barrels and was focused on developing the Manifa oil field to compensate for declines at other deposits.

Aramco started pumping crude from Manifa this month and plans to produce 500,000 barrels a day of Arabian Heavy crude from the field by July and 900,000 barrels by the end of 2014. Al-Naimi said in June 22 that year that oil from five “mega” fields could be used to boost capacity. The country raised its capacity to about 12.5 million barrels a day in 2009, from 10 million barrels, and has kept it at that level since then.

Strategic Goal
The country’s strategic goal is to maintain sufficient spare oil production capacity to offset global crude-supply interruptions, Prince Turki said in his speech this month. It has an unused 2.5 million barrels a day of capacity, which is enough to “almost instantly replace all of Iraq’s oil exports,” he said. Iraq overtook Iran last year to become the second-largest producer in OPEC, trailing only Saudi Arabia. The prince made his remarks in a speech entitled “Saudi Arabia’s New Foreign Policy Doctrine in the Aftermath of the Arab Awakening.”

Saudi Arabia’s policy is also to meet rising domestic energy needs through renewable energy and natural gas, where possible, to free up oil for export, Prince Turki said. The country currently meets 40 percent of its energy needs through gas, said Prince Turki, who also served as an ambassador to U.S. until 2007.



http://www.bloomberg.com/news/2013-...capacity-will-rise-to-15-million-barrels.html

 

[trysail]

Wow ! People have known there were hydrocarbons in the Bakken for a long time but it was also known that it would cost a lot to produce it. It wasn't cost-effective until recently.

This is a perfect example of the fact that PRICES CREATE RESERVES.



____________________

http://www.bloomberg.com/news/2013-...rks-has-more-oil-than-2008-estimate-usgs.html



Bakken, Three Forks Has More Oil Than 2008 Estimate: USGS
By Mark Drajem
April 30, 2013

Oil resources in shale formations of North Dakota, Montana and nearby states are 7.4 billion barrels, U.S. government researchers said, doubling an estimate for the region made five years ago.

The U.S. Geological Survey said today the resources can be extracted using current technology and exclude those oil-shale reserves that have already been tapped or listed by industry. In 2008, the agency estimated total oil in the Bakken formation, which is within the region assessed in today’s report, was 3 billion to 4.3 billion barrels.

The agency for the first time studied the Three Forks formation, which is estimated to include 3.73 billion barrels, exceeding the recoverable oil in the Bakken. Five years ago, Three Forks, which lies further underground than the Bakken, was considered out of reach, the agency said.

“The Three Forks is up and coming,” Brenda Pierce, the USGS energy resources program coordinator, told reporters on a conference call. The formation “was the big unknown.”

Oil production in North Dakota is booming, making that state the second-largest U.S. producer after Texas, according to the U.S. Energy Information Administration. Bakken production rose 39 percent from a year earlier to 715,000 barrels of oil a day in this year’s fourth quarter, according to data compiled by Bloomberg Industries.

About 450 million barrels of oil have been produced from the area since 2008, the geological survey said in its report.

Shale gas and shale oil is produced by horizontal drilling and hydraulic fracturing, in which millions of gallons of water, sand and chemicals are injected underground to break apart rock formations and free the trapped fuel.

The Three Forks area covers about the same geographic area as the Bakken, which extends through much of North Dakota, northeast Montana and parts of South Dakota.




http://www.bloomberg.com/news/2013-...rks-has-more-oil-than-2008-estimate-usgs.html

 

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http://www.npr.org/templates/story/story.php?storyId=180583990




Oil Drilling Technology Leaps, Clean Energy Lags
by Jonathan Fahey
The Associated Press
May 2, 2013

NEW YORK (AP) — Technology created an energy revolution over the past decade — just not the one we expected.

By now, cars were supposed to be running on fuel made from plant waste or algae — or powered by hydrogen or cheap batteries that burned nothing at all. Electricity would be generated with solar panels and wind turbines. When the sun didn't shine or the wind didn't blow, power would flow out of batteries the size of tractor-trailers.

Fossil fuels? They were going to be expensive and scarce, relics of an earlier, dirtier age.

But in the race to conquer energy technology, Old Energy is winning.

Oil companies big and small have used technology to find a bounty of oil and natural gas so large that worries about running out have melted away. New imaging technologies let drillers find oil and gas trapped miles underground and undersea. Oil rigs "walk" from one drill site to the next. And engineers in Houston use remote-controlled equipment to drill for gas in Pennsylvania.

The result is an abundance that has put the United States on track to become the world's largest producer of oil and gas in a few years. As domestic production has soared, oil imports have fallen to a 17-year low, the U.S. government reported Thursday.

The gushers aren't limited to Texas, North Dakota and the deep waters of the Gulf of Mexico. Overseas, enormous reserves have been found in East and West Africa, Australia, South America and the Mediterranean.

"Suddenly, out of nowhere, the world seems to be awash in hydrocarbons," says Michael Greenstone, an environmental economics professor at the Massachusetts Institute of Technology.

The consequences are enormous. A looming energy crisis has turned into a boom. These additional fossil fuels are intensifying the threat to the earth's climate. And for renewable energy sources, the sunny forecast of last decade has turned overcast.

This is the story of how technological advances drove a revolution no one in the energy industry expected. One that is just beginning.

EXPLORING ENERGY FRONTIERS

The new century brought deep concerns the world's oil reserves were increasingly concentrated in the Middle East — and beginning to run out. Energy prices rose to record highs. Climate scientists showed that reliance on fossil fuels was causing troubling changes to the environment.

"The general belief was that the end of the oil era was at hand," says Daniel Yergin, an energy historian and author of "The Quest: Energy, Security and the Remaking of the Modern World."

As a result, Wall Street, Silicon Valley and governments were pouring money into new companies developing alternative forms of energy that promised to supply the world's needs without polluting.

Even oil and gas companies got in the game. BP had adopted the slogan "beyond petroleum" in 2000 and threw millions into its solar division. Shell partnered with another company to fire up a plant to convert agricultural waste into ethanol.

So strong was the lure of alternative energy that veterans of the oil patch began fleeing for startups.

In 23 years at Shell, David Aldous helped develop projections that showed a booming world population and rising energy demand. He also saw how hard it was for big oil companies to find enough oil every year to replace all they sold. He left Shell to join Range Fuels, a company that promised to turn wood chips into ethanol, in 2008.

"I felt we needed faster innovation," he says.

THE RACE FOR NEW TECHNOLOGY

But while the national focus was on alternatives, the oil and gas industry was innovating too. New technology allowed drillers to do two crucial things: find more places where oil and gas is hidden and bring it to the surface economically.

Large oil companies such as Exxon, Chevron, Shell and BP turned up huge discoveries offshore in ultra-deep water with the help of better sensors and faster computers that allowed them to see once-hidden oil deposits.

Onshore, small drillers learned how to pull oil and gas out of previously inaccessible underground rock formations.

For most of the oil age, drillers have looked for large underground pools of oil and gas that were easy to tap. These pools had grown over millions of years as oil and gas oozed out of what is known as source rock. Source rock is a wide, thin layer of sedimentary rock — like frosting in the middle of a layer cake — that is interspersed with oil and gas.

An engineer named George Mitchell and his company, Mitchell Energy, spent years searching for a way to free natural gas from this source rock. He finally succeeded when he figured how to drill horizontally, into and then along a layer of source rock. That allowed him to access the gas throughout a layer of source rock with a single well. Then he used a process known as hydraulic fracturing, or "fracking" to create tiny cracks in the rock that would allow natural gas to flow into and up the well.

The United States, which was facing a gas shortage five years ago, now has such enormous supplies it is looking to export the fuel in large volumes for the first time.

The common wisdom in the industry was that the process Mitchell had invented for natural gas wouldn't work for oil. Oil molecules are bigger and stickier than gas molecules, so petroleum engineers believed it would be impossible to get them to flow from source rock, even if the rock were cracked by fracking. But Mark Papa, the CEO of a small oil and gas company called EOG Resources, didn't accept that.

"The numbers were too intriguing, the prize was so big," he remembered.

He thought there could be as much as a billion barrels of oil within reach in Texas, North Dakota and elsewhere — if only he could squeeze it out.

In 2003, he had a "eureka!" moment while poring over pictures of rock. Sections of a 40-foot-long column of source rock had been run through a CT scanner, the same type used to peer into the human body.

He saw something in the source rock sections the rest of the industry didn't know was there: a network of passageways big enough for oil molecules to pass through. Papa believed the passageways could act like rural roads for the oil to travel through. Fracking could then create superhighways for the oil to gather and feed into a pipe and up to the surface.

EOG began drilling test wells, and in 2005, Papa got some results from one in North Dakota that made him realize oil could flow fast enough to pay off.

"It was kind of like holy cow," he says. "My first thought was we need to replicate this, make sure it's not a freak result."

It wasn't. EOG snapped up land in a similar formation in South Texas known as the Eagle Ford Shale for $400 an acre when his competition thought it would never produce much oil. That land now goes for $30,000 per acre.

Papa thought the Eagle Ford might hold 500,000 barrels of oil. The Department of Energy now predicts it holds 3.4 billion. Some even expect 10 billion, which would make it the biggest oil field in U.S. history.

SMART DRILLS, RIGS THAT CAN WALK

But even after drillers figured out how to find oil and gas deep offshore and in onshore source rock, they still needed to develop technology that would make it economical.

At the tip of every oil or gas drill is a rotating mouth of sharp teeth that chews through rock. In the past, these drill bits could only dig straight down. Now they are agile enough to find and follow narrow horizontal seams of rock.

The drilling-services company Baker Hughes has designed a bit that can change directions underground, without having to be drawn back up to the surface, reducing drilling time by as much as 40 percent.

Behind the drill bit, attached to a long line of steel known as the "drill string," is an array of sensors. The sensors bombard rock with subatomic particles and measure the gamma radiation that bounces back. They assess how easily electricity flows through the rock and underground fluids. They analyze the magnetism of the rock and how it vibrates — both up and down and side to side — while drilling.

"To the layman, it looks like dumb iron, but you'd be shocked about what's inside," says Art Soucy, president of global products and services at Baker Hughes.

All this information is sent to engineers via fiber-optic cables. They run the information through supercomputers as powerful as 30,000 laptops to create a picture of the earth thousands of feet below the surface.

The people analyzing this data — and even directing the drill bits — are often sitting hundreds of miles away. Shell's Pennsylvania drilling operations are directed from a center in Houston, where experienced drillers monitor the progress at several sites across the country from a single room.

And when the drilling is done, the rig itself can "walk" a hundred feet or so to another location and start drilling again. In the past, rigs had to be taken down and reassembled, which could take days. New rigs are built on sliding "shoes" that allow hydraulic lifts to shuffle the rig forward in short steps.

"It has made possible things that were unthinkable 10 years ago," says Claudi Santiago, managing director at First Reserve Corp., a private-equity firm that invests in energy companies.

Now, drillers are finding oil faster than the world is using it. At the end of 2001, the industry had enough "proved oil reserves" to satisfy world demand for 45 years, according to BP's annual statistical review, a closely watched study. By the end of 2011 that had grown to 51 years — even though a decade's worth of oil had been used and daily demand had grown 14 percent. And "proved reserves" refers to oil that can be economically tapped using today's technology. Tomorrow's methods could yield even more.

This is good news for a global economy that remains dependent on fossil fuels, but it's terrifying to climate scientists.

"If we're willing to go down this road of squeezing whatever petroleum we can out of the earth, we can easily get carbon dioxide levels up to unfathomable levels and put in motion what would be dramatic or catastrophic changes in our climate system," says Michael E. Mann, a geophysicist and director of the Earth System Science Center at Penn State University.

RENEWABLES PROGRESS, BUT NOT FAST ENOUGH

Renewable technologies have had their successes. The average cost of a solar power system has fallen by 31 percent in the last two years. Solar now generates six times more electricity in the U.S. than it did a decade ago, and wind produces 14 times more. Most major automakers offer some type of electric vehicle.

And this success has come despite the fact that renewable energy's major benefit — that it doesn't pollute — is given little or no value in the marketplace because most governments haven't adopted taxes or penalties for fossil fuel pollution.

But the outlook for wind, batteries and biofuels is as dim as it's been in a decade. Global greenhouse gas agreements have fizzled. Dazzling discoveries have been made in laboratories, and some of these may yet develop into transformative products, but alternative energy technologies haven't become cheaper or more useful than fossil fuels.

Solar, wind and geothermal sources together accounted for 4.8 percent of U.S. power generation last year. Ten percent of U.S. gasoline demand was satisfied with corn ethanol, but ethanol and other fuels made from non-food sources have yet to hit the market.

"In many cases, renewables aren't ready for primetime yet," says George Biltz, vice president for energy and climate change at Dow Chemical, which continues to work on a host of renewable technologies.

Likewise, electric cars have not enjoyed the success many expected. The battery alone in an electric car costs as much as a new gasoline-powered car, and electric vehicles are not selling nearly as fast as once projected. General Motors expected to sell 60,000 Chevy Volts globally last year, but sold just half that many. Sales of Nissan's all-electric Leaf grew 22 percent around the world last year to 26,000, short of Nissan's projected 50 percent growth.

The cost of wind and solar power has declined, but the price of electricity made with newly cheap fossil fuels has fallen too, making it harder for wind and solar to compete.

"Renewables are now under scrutiny. They haven't made the kinds of quantum leaps we have seen in the oil and gas industry," says First Reserve Corp.'s Santiago, who now shuns investments in alternatives.

David Aldous, the former Shell executive, learned that lesson while trying to turn wood chips into ethanol at Range Fuels. The system that fed the chips into a gasification chamber didn't work well, and the project failed.

"Things don't always scale from the petri dish to the demo plant and then to the commercial plant. It's just part of building up a new industry," Aldous says.

Range went out of business in 2011, and it was hardly alone. Dozens of biofuel, battery and solar companies failed even though federal and state governments supported alternatives with loans and grants, and mandated their use. Others are limping along.

Pacific Ethanol, which traded near $300 per share in 2006, now trades for 28 cents. Amyris, an advanced biofuels company, traded near $34 a share as recently as last year, but now trades at $2.74. The battery maker A123 was forced to file for bankruptcy protection last year, three years after going public. An index of clean energy companies that was first traded in March 2005 is down 69 percent since then. A similar index of traditional energy companies is up 75 percent over the same period.

THE NEXT 10 YEARS

This dark period for alternative energy could last for years. With government debt soaring and no more worries about running out of oil, many renewable subsidies are being scaled back.

"The world is completely different now," MIT's Greenstone says.

But there are still hundreds of companies, including fossil fuel giants, working on new renewable-energy projects. ExxonMobil is investing in Synthetic Genomics, a company started by the geneticist J. Craig Venter to try to create strains of algae that will produce fuels. BP and Shell continue to work on ways to turn plant waste into fuels.

California, meanwhile, set the nation's most ambitious renewable energy goals and is on track to meet them. One-fifth of the power delivered by the state's three biggest utilities now comes from renewables, not including large hydroelectric dams. By 2020, that portion will rise to one-third.

President Barack Obama in March proposed using $2 billion in federal oil and gas royalties to invest in clean energy technology research. Obama is also expected to promote renewables through pollution regulations, if not with new laws.

And for all the world's newfound oil, prices are still high because developing nations are consuming more.

"It's not time to write the epitaph yet," Aldous says. Eventually the global economy will fully recover, he says, and demand for energy of all kinds will increase.

"New sources of energy are going to be in vogue again," he says.

Experts didn't see the oil and gas boom coming five years ago. It's certainly possible the world will change direction again in the next five years.

But EOG's Papa says oil and gas companies will just invest in even more sophisticated technology. He estimates that current techniques pull only 6 percent of the oil trapped in source rock to the surface. Learning to double that would yield yet another enormous trove of hydrocarbons.

"Now we go into the next phase of technology," he says. "How are we going to get the rest of it out of the ground?"




http://www.npr.org/templates/story/story.php?storyId=180583990

 

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XOM Market capitalization: ~$400 billion

http://thomson.mobular.net/thomson/7/1465/4737/document_0/page_23/images/image-03.png



LUKoil Market capitalization: ~$48 billion

LUKoil:
http://www.lukoil.com/materials/images/Reserves/2012/Clipboard03_eng.jpg

​

 

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There sits Gazprom with Western-audited (DeGolyer & McNaughton ) proved hyrdocarbon reserves (primarily gas) of more than 100 billion barrels equivalent, owning the country's entire pipeline system, a state-granted gas export monopoly and largely unlevered trading at a third of book value, a ratio of price-to-trailing earnings of less than 3 and a market capitalization of less than $100 billion.


For contrast's sake, ExxonMobil has proved reserves of roughly 25 billion barrels, trades at a market capitalization of about $400 billion, at a price-to-book value ratio of 2.4× and a price-to-trailing earnings ratio of 11×.

 

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Silicon Valley isn't any more high tech than this stuff:

Shell moves forward on new Gulf Mexico development at Stones
08 May 2013


Royal Dutch Shell plc (Shell) today announces a final investment decision in the Stones ultra-deepwater project, a Gulf of Mexico oil and gas development expected to host the deepest production facility in the world. This decision sets in motion the construction and fabrication of a floating production, storage, and offloading (FPSO) vessel and subsea infrastructure.


The development will start with two subsea production wells tied back to the FPSO vessel, followed later by six additional production wells. This first phase of development is expected to have annual peak production of 50,000 boe/d from more than 250 million boe of recoverable resources. The Stones field has significant upside potential and is estimated to contain over 2 billion boe of oil in place.

“This important investment demonstrates our ongoing commitment to usher in the next generation of deepwater developments, which will deliver more production growth in the Americas,” said John Hollowell, Executive Vice President for Deepwater, Shell Upstream Americas. “We will continue our leadership in safe, innovative deepwater operations to help meet the growing demand for energy in the US.”

The Stones field is located in 9,500 feet (2,896 meters) of water, approximately 200 miles (320 kilometers) southwest of New Orleans, Louisiana, and was discovered in 2005. The project encompasses eight US Federal Outer Continental Shelf lease blocks in the Gulf of Mexico’s Lower Tertiary geologic trend. Shell has been one of the pioneers in the Lower Tertiary, establishing first production in the play from its Perdido Development.

An FPSO design was selected to safely develop and produce this ultra-deepwater discovery, while addressing the relative lack of infrastructure, seabed complexity, and unique reservoir properties. With an FPSO, tankers will transport oil from the Stones FPSO to US refineries, and gas will be transported by pipeline.


The launch of the Stones development is a key milestone as Shell continues to grow deepwater exploration and development in the Gulf of Mexico, having made significant progress recently on the Mars-B development project with the arrival of the Olympus tension leg platform. Shell is also in the concept selection phase for the Appomattox and Vito discoveries in the Gulf of Mexico.

Shell holds 100% interest and will operate the Stones development.


• A turret with a disconnectable buoy will allow the FPSO vessel to weathervane in normal conditions and to disconnect from the well system and sail to safe areas in the event of adverse weather conditions.

• A lazy wave riser configuration will be used, consisting of a steel catenary riser with buoyancy added with an arch bend to decouple the FPSO dynamic motions and subsequently increase riser performance.

• A combination of polyester rope and chain comprises the ultra-deepwater mooring system holding the FPSO on station.

• Multiphase seafloor pumping is planned for use in a later phase to pump oil and gas from the seabed to the FPSO, increasing recoverable volumes and production rates.

 

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http://www.bloomberg.com/news/2013-...-oil-at-iara-discovery-energy.html?cmpid=yhoo



Petrobras Said to Struggle Pumping Oil at Iara Discovery
By Peter Millard and Rodrigo Orihuela
May 19, 2013

Petroleo Brasileiro SA is finding it hard to pump oil at one of Brazil’s largest prospects, three people with knowledge of the project said, signaling its venture with BG Group Plc and Galp Energia SGPS SA may have higher costs or slower development than at other offshore fields.

Petrobras, the world’s biggest producer in deep waters, has encountered low permeability at sections of the Iara field, said the people, who spoke on condition of anonymity because results haven’t been made public. That means more costly techniques, such as hydraulic fracturing, or fracking, may be needed to get oil flowing at Iara, where single deep-water wells have already cost more than $100 million apiece, one of the people said.

BG of the U.K. and Portugal’s Galp are relying on Petrobras as concession operator to accelerate output at their wells in the Iara discovery. Petrobras instead may prioritize areas of the field that flow better rather than employ fracking miles below the South Atlantic seabed, said Cleveland Jones, a geology professor at Rio de Janeiro State University.

“The option is to go for the easy stuff and the difficult stuff later, the path of least resistance,” Jones, who has researched fields with the same geology, said by phone from Rio. “Why drill a much more expensive well when you don’t need to?”

Iara, about 230 kilometers (143 miles) out to sea from Rio, is one of Brazil’s five largest discoveries. It’s in the same exploration block as Lula, the world’s biggest discovery in more than a decade. That’s where Petrobras beat production expectations and individual wells pump as much as 36,000 barrels a day. Both fields are known as “pre-salt” -- in a reference to their geological formation over time.

‘Special Techniques’
In 2008, Petrobras estimated as much as 4 billion barrels of recoverable reserves at Iara, or enough to meet Brazilian demand for more than five years. The recent tests suggest the quality of the pre-salt reservoirs aren’t uniform. Brazil plans an auction for more exploration licenses in November.

The state-run producer may eventually use “special techniques for stimulation and well geometry” at areas of Iara to optimize productivity, Petrobras said May 13 in an e-mailed reply to questions. The Rio de Janeiro-based company said it will finish a fourth well and start a fifth before the end of the year at the field where it maintains positive expectations.

Petrobras declined to comment on any possible changes to the reserve estimates and said in the e-mail that its business plan calls for two production systems at the area by the end of 2018. That compares with seven at the Lula field.

‘Slightly Poorer’
BG, the U.K.’s No. 3 gas producer, has said it expects existing assets in Brazil to deliver more than a third of its production in 2020. Lisbon-based Galp has said it’s counting on Brazilian crude to help curb dependence on refining and fuel sales in Portugal and Spain.

Pre-salt fields will double Petrobras’s output by 2020 after it started production in 2009, according to the company’s business plan.

The partners are examining plans to expand Iara, which has “similar oil in place to Lula, but with slightly poorer reservoir properties,” BG CEO Chris Finlayson said May 14 in London. A press officer for BG’s Brazil unit, who isn’t an authorized spokesperson, referred questions on Iara to operator Petrobras. Pedro Marques Pereira, a spokesman at Lisbon-based Galp, also referred questions to Petrobras in an e-mail.

BG has a 25 percent stake in the BM-S-11 block that includes Iara, and Galp has 10 percent. Growing output at Brazil’s pre-salt helped both BG and Galp beat earnings estimates in the first quarter.

‘Different Ballgame’
The Brazilian producer is already developing pre-salt fields it discovered after Iara at a faster pace. Franco, which Petrobras bought from the government in 2010 as part of a $70 billion share sale, is set to start production in 2016 from two separate production systems. The field, where Petrobras will sell all of the oil itself, will have five systems in place by the end of 2019, according to the business plan.

Petrobras drilled its first pre-salt well at BM-S-10 in 2005, where it discovered the Paraty field. Drilling a single well in the area has cost in excess of $200 million. It costs about 50 percent more to drill horizontal wells and frack offshore reservoirs, said Jason Kenney, an analyst at Banco Santander SA in Edinburgh.

“You’re now in a different ballgame of drilling, it’s about as complex as a well can get,” Gianna Bern, president of Brookshire Advisory & Research Inc. in Chicago, said by telephone, without giving a cost estimate. “They’ll assess where it fits with the larger strategy. They’ll always go for the most economical barrels first.”

Returned Areas
Petrobras has lowered drilling costs in the pre-salt by reducing times to 70 days in 2012 from 134 in 2006, according to the company’s business plan. The region as a whole has beaten the company’s targets. In 2010 Petrobras planned to be pumping 241,000 barrels a day from the pre-salt by 2014. In March Brazil’s pre-salt oil and gas output reached 349,600 barrels a day, according to the National Petroleum Agency, or ANP.

Petrobras has returned areas of the pre-salt to the government after initial exploration failed to show commercial potential. The biggest producer in waters deeper than 1,000 feet returned 28 percent of BM-S-10 exploration block, including the Macunaima prospect it discovered in 2011, to the oil regulator last year, according to ANP’s website.

Exxon Mobil Corp., Hess Corp. (HES) and Petrobras returned the BM-S-22 block to the regulator a year ago after failing to find commercial deposits.

“Not all the news has been good,” Fernando Siqueira, a former Petrobras manager and current vice-president of the association of Petrobras engineers, said by phone from Rio. “Exxon drilled three wells and found nothing.”

First Oil
Petrobras plans to pump its first barrels from Iara in 2017 after installing a production vessel at the site, according to its business plan. The output will come from the Iara Horst well, 8 kilometers from the initial find.

Iara Horst has “better reservoir characteristics” than the first well it drilled in the area, Petrobras said in a March 2011 statement. It was the second pre-salt field, after Lula, where Petrobras gave specific reserve estimates.

Petrobras’s overall success rate in the pre-salt is at 82 percent, higher than the 64 percent rate for its entire Brazil operations, according to information on its website. Globally, about 35 percent of wells find oil and natural gas.




http://www.bloomberg.com/news/2013-...-oil-at-iara-discovery-energy.html?cmpid=yhoo

 

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http://www.bloomberg.com/news/2013-...-terminal-partly-owned-by-conocophillips.html



Gas Export Approval Not Seen Signaling U.S. Permit Flood
By Jim Snyder and Edward Klump
May 17, 2013

The conditional approval of a natural gas export terminal in Texas doesn’t necessarily open the floodgates for overseas sales as the U.S. weighs how best to use its growing energy resources.

The U.S. Energy Department said yesterday that exports from the Freeport LNG project, partly owned by Dow Chemical Co. and Osaka Gas Co., according to the venture’s website, offered net economic benefits and reflected the “transformative impact” of record gas production from hydraulic fracturing in shale rock formations.

How much of that bonanza should be sold to non-U.S. customers has been hotly debated in Washington in recent months as the Energy Department weighs 20 applications for export terminals. While industry groups welcomed the decision, analysts were split on how quickly the export facilities will go forward.

“I think we need to see more than one to get an idea of what the pace is going to be,” said Randy Bhatia, an analyst with Capital One Southcoast in Houston. The size and scale and complexity of a project may effect the pace of review, he said.

“We don’t think it’s going to open the floodgates” for the department’s approval of other applications, Mihoko Manabe, vice president and senior credit officer for Moody’s Investors Service Inc., said in a phone interview.

Manabe said she expects the Energy Department to approve LNG export facilities proposed by Dominion Resources Inc. of Richmond, Virginia, and Sempra Energy of San Diego.

Sabine Pass
In addition to the Freeport project, the agency has already approved Cheniere Energy Inc.’s Sabine Pass export terminal in Louisiana.

“The four facilities, we believe, have a good chance of going forward,” said Manabe, lead author of a Moody’s report issued May 1 on the prospects for natural gas exports.

The decision drew wide praise from industry groups, as they called on the department to quickly approve the remaining applications. The announcement was “welcome news,” said Bill Cooper, president of the Center for Liquefied Natural Gas in Washington. Natural gas is cooled to a liquid so that it can be transported by tanker to overseas markets.

“The rain cloud in that otherwise beautiful sky is we don’t know the timeline for moving forward,” Cooper said in an interview.

Erik Milito, director of upstream and industry operations for the American Petroleum Institute in Washington, said in a statement that the announcement was a “step in the right direction.”

More Pollution
The Sierra Club criticized the decision, saying it would lead to more development of natural gas.

“More drilling means more fracking, more air and water pollution, and more climate fueled weather disasters like last year’s record fires, droughts and superstorms,” said Deb Nardone, director of the San Francisco-based environmental group’s Beyond Natural Gas campaign.

While oil and gas producers have lobbied for unfettered exports, companies including Dow that use natural gas as an ingredient for their products have argued for limits on overseas sales, fearing they could cause prices to rise domestically.

Dow issued a statement supporting the Energy Department’s decision, saying it reflected a “measured and balanced” review of the issue. George Biltz, Dow’s vice president for energy and climate change, said the U.S. should neither block exports entirely nor open the floodgates to overseas sales.

“We like the decision because it’s not in either extreme,” Biltz said in a phone interview.

Import Terminal
Less than a decade ago, when U.S. demand for gas looked like it might outstrip supply, Dow invested in a Freeport import terminal that would now be converted for exports. That investment may mean the company would get revenue from sales to non-U.S. customers, despite its opposition to large export levels.

Biltz said Dow isn’t investing in the multibillion-dollar effort to convert the terminal for exports.

Other limited partners in the Freeport LNG development are Zachry American Infrastructure LLC and Freeport LNG Investments, according to the venture’s website. ConocoPhillips and private investor Michael Smith are co-owners of the management company overseeing the original LNG import facility.

The Energy Department cited the changing energy landscape in announcing conditional approval of the Freeport terminal, which is jointly operated by Freeport LNG Expansion LP, and FLNG Liquefaction LLC. The project calls for the installation of refrigeration units, storage tanks and other equipment alongside its existing gas-import terminal on Quintana Island about 65 miles (105 kilometers) south of Houston.

Transformative Impact
“The development of U.S. natural gas resources is having a transformative impact on the U.S. energy landscape, helping to improve our energy security while spurring economic development and job creation around the country,” the department said in its news release.

Bill Gibbons, a department spokesman, said President Barack Obama’s administration was addressing the issue “in a responsible way” and would weigh applications on a case-by-case basis.

After a preliminary review, it seems “the order provides us everything that we requested in terms of the authorization and we commend the Department of Energy on the thoroughness of their review and consideration of exports and getting to the right result,” John Tobola, general counsel of Freeport, said in a telephone interview yesterday.

If all 20 projects were to win approval, they could ship the equivalent of 41 percent of the total U.S. production this year, according to Energy Department data.

FERC Approval
The Freeport LNG project must still win approval from the Federal Energy Regulatory Commission.

The big hurdle was thought to be the Energy Department, which must decide if the projects are in the national interest. The department concluded that exports from the Freeport facility are “likely to yield net economic benefits” to the U.S.

Freeport would be able to export as much as 1.4 billion cubic feet of natural gas a day for 20 years. In May 2011, the department conditionally approved Cheniere Energy Inc.’s Sabine Pass LNG Terminal in Louisiana for a rate of as much as 2.2 billion cubic feet a day.

The Energy Department’s action yesterday is “an indication that other projects, including our own Cameron LNG, will receive this authorization soon,” Mark Snell, president of Sempra Energy, said in a statement.

The power company is awaiting federal approval for exports from a $6 billion to $7 billion expansion of its Cameron LNG project in Hackberry, Louisiana.

‘Narrow Window’
“There is a narrow window opportunity for U.S. companies to participate in the global LNG market,” Snell said.

In its release, the Energy Department cited an Energy Information Administration forecast projecting production to reach a record 69.3 billion cubic feet a day in 2013.

Senator Ron Wyden, an Oregon Democrat and chairman of the Senate Energy and Natural Resources Committee, said the Energy Department’s decision to review applications individually was consistent with his view that a “measured approach on exports will provide the greatest advantage for the U.S. economy.”




http://www.bloomberg.com/news/2013-...-terminal-partly-owned-by-conocophillips.html

 

[trysail]

http://www.bloomberg.com/news/2013-...hunned-as-putin-weighs-share-sale-energy.html



Russia’s Oil Champion Shunned as Putin Weighs Share Sale
By Stephen Bierman
June 20, 2013

Russia’s global oil champion has yet to win over investors.

OAO Rosneft Chief Executive Officer Igor Sechin addresses shareholders today for the first time since his $55 billion acquisition of TNK-BP created the world’s largest publicly traded crude producer. The shares are down 17 percent this year, under-performing Moscow’s benchmark index as well as competitors OAO Lukoil and OAO Surgutneftegas and wiping about $22 billion from the value of the company.

The slump widened the valuation gap between Rosneft and the global oil producers it wants to emulate and may stymie Russia’s plans to sell a further 19 percent of the company. Concerns range from corporate governance -- Rosneft’s refusal to buy out minority shareholders in TNK-BP rankles some investors -- to capital spending plans and rising debt.

“They have taken over the most productive, efficient set of energy assets in Russia and many in the market fear Rosneft are already starting to impact them negatively,” said Michael O’Flynn, managing director of UFG Asset Management, which has $1.5 billion under management in Russia and doesn’t hold Rosneft shares.

Sechin, a former deputy prime minister and a long-time ally of President Vladimir Putin, plans to show the company’s desire for international standards of governance by electing ex-Morgan Stanley CEO John Mack, former Exxon Mobil Corp. vice president, Donald Humphryes, and BP Plc CEO Bob Dudley to the board this week.

Extensive Experience
“All of them have extensive experience in the oil and financial sector, which will undoubtedly increase the overall level of corporate governance,” Sechin said during a call with investors in April. The TNK-BP deal was completed in March.

Rosneft’s press service declined to comment beyond Sechin’s public statements.

Rosneft, 70 percent owned the Russian state, is holding its shareholders meeting to coincide with the St. Petersburg Economic Forum, which will see Putin welcome global business leaders and pitch for foreign investment.

Russia, seeking to raise money from the sale of state assets, may put 19 percent of Rosneft up for sale as early as this year, Economy Minister Andrei Belousov said in April.

State Goals
Still, the risk of investing in companies controlled by the Russian government, where the goals of the state may be put before shareholders, helps explain Rosneft’s discount to international oil companies, said Alexander Burgansky, an analyst at Okritie Financial Corp.

Rosneft shares trade at a price equal to 6.1 times earnings. That compares to 11.5 times at Exxon Mobil, 9.4 times at Chevron Corp. and 8 times for Royal Dutch Shell Plc.

Rosneft gained as much as 6.1 rubles, or 2.8 percent, to 225.44 rubles in Moscow trading today. The shares traded at 224.39 rubles at 1:04 p.m. local time.

“Sentiment has been undermined by major corporate governance concerns,” said Lev Snykov, a partner at Greenwich Capital in Moscow. “Investors worry Rosneft might lose efficiency as it gets bigger and will no longer be focused on their interests.”

Rosneft had to borrow to finance the TNK-BP acquisition and the company’s debt to equity ratio rose to 66 percent in the first quarter from 26 percent at the end of 2012, according to data compiled by Bloomberg. While capital spending will only rise by the rate of inflation this year to about 480 billion rubles ($14.9 billion), the company has pledged to invest $18 billion upgrading oil refineries by 2018.

BP Stake
A revival in Rosneft’s share price is important for BP, which took an 18.5 percent stake in the company as part of the TNK-BP deal, making the London-based company the largest foreign equity investor in Russia.

“Improving the total shareholder return via dividends and price appreciation is a primary focus for BP in its relationship with Rosneft,” Scott Sloan, president of BP Russia, said in an interview in Moscow. “In order to support this, BP is willing to work with Rosneft to assist in implementing the best technology to fit its projects.”

Winning back investors won’t be easy after Rosneft annulled a dividend for last year’s profit at TNK-BP’s traded unit, TNK-BP Holding, according to Eric Kraus, who manages about $200 million at Nikitsky Capital. Instead of paying a dividend, Rosneft may borrow cash from TNK-BP Holding, bypassing the minority owners who still own about 5 percent of the company.

‘Rightful Dividend’
“Depriving the minority investors of their rightful dividend is penny-wise but extremely pound-foolish,” said Kraus, who doesn’t hold any Rosneft shares. “If this is how they treat minorities when they are trying to drum up interest in a privatization, how will they treat them once they have their cash?”

Still, Rosneft’s production and reserves remain world-leading for a publicly traded company. Oil and gas output equivalent to 4.7 million barrels a day and 33.9 billion barrels of reserves both top Exxon. Rosneft also holds rights to acreage on Russia’s Arctic shelf, one of the world’s largest unexplored oil frontiers.

Production from offshore Arctic fields could start as early as 2018, Sechin said at today’s shareholder meeting.

The company expects $12 billion in cost savings by 2016 through combining pipelines, trading and transportation with TNK-BP, Sechin said.

Share Performance
The market for Russian crude oil has weighed on Rosneft’s share performance. Urals crude export prices have slid from a high of $116.76 a barrel on Feb. 8 to as low as $95.28 on April 17. Rosneft’s shares traded at 219 rubles in Moscow yesterday implying a current valuation of $72 billion.

Pressure on the commodities sector and the corporate governance issue are bringing Rosneft shares down, said Tim McCarthy, who helps manage $1 billion at Valartis Asset Management in Geneva.

“Companies need to be more efficient when their key product prices are falling,” McCarthy said. It will be key for Rosneft to stop TNK-BP talent from leaving the company, he said.

About 90 percent of the managers at TNK-BP Management, or 1,600 people, have made the switch to Rosneft, according to a statement on the company website. Even so, executives from TNK-BP in production, planning and procurement as well as the head of TNK-BP’s largest production unit, Samotlor, have already been replaced, according to a May press release. Those departures are in addition to previous top management of TNK-BP, most of whom left in March.

“I suppose these big names on the board will help improve sentiment, but investors will want to see action,” McCarthy said. “Stemming the outflow of good managers from the TNK-BP team would be a start.”




http://www.bloomberg.com/news/2013-...hunned-as-putin-weighs-share-sale-energy.html

EIARussia
RussiaEIA
http://www.eia.doe.gov/countries/cab.cfm?fips=RS

 

[trysail]

Wow!


The cracks in the method of pricing of Gazprom's natural gas exports to Europe are spreading. This is a big deal.


For those unaware of it, Gazprom is— by far— the world's largest corporate owner of natural gas reserves. Their barrel-equivalent reserves dwarf ExxonMobil's (by a factor of at least 3×). Europe gets more than a quarter of its natural gas supplies from Gazprom.


The cracks in the linkage of Gazprom's natural gas export price to petroleum can be largely attributed to the private investment of hundreds of billions of dollars into the worldwide development of the liquefied natural gas ("LNG") business that have partially transformed the natural gas industry from one characterized by regional pricing to one increasingly influenced by worldwide prices.


________________


http://www.bloomberg.com/news/2013-...rom-deals-of-oil-price-after-arbitration.html



RWE Sees End of Europe’s 40-Year-Old Gas Pricing for Gazprom
By Tino Andresen
July 9, 2013

RWE AG expects a 40-year-old system for setting European gas prices that has cost Germany’s second-largest utility hundreds of millions of euros to be cast aside after an arbitration ruling against Russia’s OAO Gazprom.

A Vienna tribunal decided RWE paid Gazprom too much from May 2010 and the Moscow-based gas-export monopoly needed to introduce market rates for the fuel, according to the German power producer. In reaction, Russian President Vladimir Putin defended the decades-old regime of linking rates to oil indexes.

“We have a solution which partly replaces oil indexation by gas indexation,” said RWE Chief Financial Officer Bernhard Guenther in an interview at its head office in Essen. “Going forward we will claw the small money back which we might now still lose on the remaining oil-indexed part.”

RWE, now in price talks with Gazprom, has fought to end the tradition of linking supply deals to oil prices that was set up before European gas markets for immediate delivery developed. Weakening demand for gas means the amount utilities can charge customers for the fuel has sunk relative to Gazprom’s prices.

The ruling “will be taken into consideration in the new talks,” Guenther said. Seeking arbitration, instead of settling with Gazprom like larger rival EON SE, was successful, he said. RWE was the only European customer to complete arbitration.

Limited Links
RWE has declined by 8.9 percent in Frankfurt trading since announcing the ruling June 27, while EON is down 1.1 percent. RWE advanced 0.2 percent to 22.44 euros by 3:17 p.m. today.

The ruling brought “quite limited” links to gas indexes, Gazprom Export, responsible for contracts, said in a statement. “We consider the ruling objective, weighted and taking into account principles of long-term contracts, arguments from both sides and objective processes that happened on the market.”

EON, Gazprom’s biggest European customer, reached a deal with the Russian company on gas prices a year ago that added about 1 billion euros ($1.3 billion) to half-year results. RWE said on July 1 the effect of the arbitration ruling was “in line” with its expectations, without providing a figure. The company will get a similar windfall to EON, Spiegel reported.

“The award was a necessary step to eliminate the anachronism of oil-price indexation,” said Thomas Deser, a portfolio manager at Union Investment GmbH who is responsible for the fund’s 57 million-euro stake in RWE. The company may have avoided raising its outlook after the ruling because of possible losses in Egypt operations, he said.

Egypt Sale
RWE plans to sell its Dea oil and gas production unit in the country to raise as much as 5 billion euros, according to a person familiar with the matter who asked not to be identified.

The utility is also studying mothballing power plants where losses are higher than the cost of closing them, Guenther said.

RWE is cutting capital and operating expenditure to ensure it can generate cash and plans to reduce the ratio of net debt to earnings before interest, tax, depreciation and amortization in the medium term to 3 from 3.5, he said. It won’t likely pay down debt without disposals until 2015, when it can generate cash after paying expenses and dividends, Guenther said.

In March, RWE abandoned a target of 7 billion euros of disposals by the end of the year as asset prices were too low.

RWE’s shares, down 28 percent this year, have been “driven by the developments in power generation,” Guenther said. It’s a “kind of seismic shift from the old business model.”




http://www.bloomberg.com/news/2013-...rom-deals-of-oil-price-after-arbitration.html

 

[thør]

And my friend who married a Chinese woman he met on the internet tells me one should have no issues dealing with Chinese companies.

Right.....

 

[trysail]

And my friend who married a Chinese woman he met on the internet tells me one should have no issues dealing with Chinese companies.

Right.....

Nickel prices..

C'est la guerre.

See also:

http://chart.finance.yahoo.com/z?s=S.TO&t=my&q=l&l=off&z=l&a=v&p=s&lang=en-US&region=US​

Sherritt International posts loss due to lower nickel prices


( http://www.reuters.com/article/2013...News&feedType=RSS&feedName=companyNews&rpc=43 )

 

[trysail]

It's a business that requires one to think in terms of decades.

[emphasis supplied]

______________



http://www.bloomberg.com/news/2013-...h-unlocks-1-5-trillion-oil-offshore-u-s-.html



Wildcatter Hunch Unlocks $1.5 Trillion Oil Offshore U.S.
By Edward Klump
September 13, 2013

Texaco Inc. geologist Robert Ryan didn’t suspect he was helping change the energy future of the Gulf of Mexico when he gave the go-ahead for a well that would break the world record for deep-water drilling.

The project known as BAHA, undertaken in 1996 by Texaco and its partners, Royal Dutch Shell Plc, Amoco Corp. and Mobil Corp., was a dry hole. That normally would’ve made it a flop. Instead, BAHA’s discovery of oil-rich sands where none were thought to exist was the first step in unlocking a $1.5 trillion trove of crude that’s revived the prospects of a body of water many thought had long ago given up most of its fossil-fuel riches.

Just as technology has allowed explorers to tap vast new oil and natural gas supplies in onshore shale fields, it’s now reinventing the Gulf. BAHA was the first deep-water well to try plumbing the Lower Tertiary, a layer of the earth’s crust formed more than 25 million years ago after mammals had replaced dinosaurs as the dominant life form.

A series of recent finds in the ultra-deep has profoundly changed the thinking on U.S. offshore geology, with 2013 seeing the Gulf of Mexico become one of the most promising frontier oil plays in the world and the fastest-growing offshore market.

New seismic equipment and computer power has allowed explorers to see into once-invisible layers of rock. Engineering innovations enable them to drill five miles into the earth through waters more than 10,000 feet deep, where temperatures are more than hot enough to boil water and high pressures approach the weight of four cars resting on one square inch.

Record Output
The Gulf is heading for record deep-water output equivalent to almost 2 million barrels of oil a day in 2020, according to industry researchers Wood Mackenzie Ltd. The U.S. estimates about 15 billion barrels of recoverable oil remain to be found in the Lower Tertiary.

While most U.S. shale fields have now been identified and mapped, the Gulf is seen as having much bigger yet-to-be-discovered potential -- 48 billion barrels of oil compared to the 13 billion barrels estimated for onshore and coastal oilfields, according to U.S. data.

Investment is pouring in, with 42 drilling rigs operating in 1,000 or more feet of water as of Sept. 9 -- 35 percent more than four years earlier, according to U.S. data on the Gulf. By the end of 2015, 60 rigs are slated to be working in the deep water off U.S. shores, estimates Brian Uhlmer, an analyst at Global Hunter Securities LLC in Houston.

Regaining Interest
It’s a dramatic turnaround for the Gulf, which saw interest wane in the previous decades as old wells dried up and explorers shifted their attention to search Africa, Latin America and Asia. By October 1989, offshore crude output had dwindled to 678,000 barrels a day, down 28 percent from 943,000 barrels five years earlier, according to Energy Department data.

Attempts by producers such as Chevron Corp. and Exxon Mobil Corp. to move from the Gulf’s shallower depths to look for oil in deeper waters farther offshore had proved disappointing.

“Deep water wasn’t working for us,” said Ryan, now Chevron’s chief of global exploration, who worked for Texaco in the 1990s before it was acquired by Chevron. Yet they still weren’t ready to walk away.

In 1995, geologists and engineers from four of the world’s biggest oil companies -- Texaco, Amoco, Shell and Mobil --packed into a Houston conference room to discuss what was described as the biggest undrilled geologic structure left in the continental U.S.

The companies had joined together a block of leases in the Gulf of Mexico that had languished for about 10 years. They were excited by the massive up swell of rock that formed the subterranean structure -- the type of dome that in other places had yielded abundant oil and gas. But doubts ran high about drilling.

Deep-water Record
The prospect was in deeper water than ever had been drilled -- 7,625 feet. Based on current geologic understanding, the scientists worried the formation wouldn’t contain the kind of oil-bearing sands that would justify drilling such an expensive frontier well. “It was thought that sands settled closer to shore,” said Ryan, who at the time was in charge of Gulf of Mexico exploration for Texaco.

After hours of tense debate, the four partners agreed to drill. It was risky, yes. It also promised to reveal a vast new store of knowledge about the potential of the deep water Gulf. The only way to mitigate the risk of future drilling is to get a well in the ground and find out what’s there.

“Somebody has to drill that first well,” Ryan said, recalling the difficult decision in an interview last month in his Houston office. It’s all about building the story, well by well. “You’re piecing it together,” he said.

BAHA Compromise
The next vote -- on what to name the well -- was almost as contentious. Naming privilege generally goes to the majority partner and operator, while the four companies were equal owners. Squabbling followed, Ryan recalls, until one of the geologists in the room, eager to step out for a smoke, hit on the solution: each company contributed a word, and the first letter of each word formed the name. So Brachiosaurus (Shell), Alpha Centauri (Texaco), HI-C (Mobil) and Anaconda (Amoco) became BAHA.

Shell, which had a drilling rig under contract ready to start, was named the operator of the project.

As feared, the BAHA well was a dry hole. Technical difficulties forced the companies to stop drilling before they’d even hit their target depth. But the real value of the well was in what it did find: a layer of oil-bearing sand where they didn’t think it would exist.

“More sand than you could shake a stick at,” Ryan said. “It busted every model we had.”

Next Act
Ryan still has the custom shirt and hat made to commemorate the well, with the embroidered BAHA logo underscored by the bragging point: “Ultra-Deepwater.” The shirt was a testament to the landmark nature of the well, since such souvenirs are usually reserved for discoveries, not dry holes.

The results made BAHA 2 a no-brainer, though it took five more years for the companies to study the formation and decide where the next well should go.

By 2001, Mobil was part of Exxon, Amoco was part of BP Plc (BP/) and Texaco was becoming part of Chevron in a wave of Big Oil mergers meant to give the companies enough heft to explore in ever-more remote and hostile regions of the world.

Even though BAHA 2 turned out to be another dry hole, it showed the extent of the oil-bearing sands in the deep water Gulf. Michael Mahaffie, a member of Shell’s exploration team, remembers watching the drilling logs transmitted to his Houston office, mapping the rock as the drill bit moved deeper into the Lower Tertiary.

‘Whopper Sand’
“I immediately flew to New Orleans to show Shell leaders what we discovered -- the ‘whopper sand,’” he recalled in an e-mail last month. “It was a major revelation to be able to correlate the seismic data to the extensive and continual sands that we found, which covered two-thirds of the deep-water Gulf of Mexico.”

John Snedden, a geologist at the University of Texas at Austin, calls BAHA 2 the “play opener” for the Lower Tertiary.

Other companies had begun exploring in and around the edges of the zone, and more wells quickly followed. BAHA 2 had shown not only the enormous potential of the Lower Tertiary sands, it also demonstrated the enormous cost, at more than $100 million per well. To be economic, discoveries needed to be big.

Shell hit oil at its Great White prospect the following year, 2002, and the company was on its way to multiple finds in the Lower Tertiary. By 2006, Shell was ready to announce plans to produce oil through a floating facility from the region known as Perdido, a project it owns jointly with Chevron and BP.

Premier Project
The Perdido complex -- which produces from the Great White, Tobago and Silvertip wells -- was the first Gulf project from the Lower Tertiary to begin output, with the companies announcing the startup on March 31, 2010.

Less than a month later, exploration stopped in the Gulf as BP dealt with the explosion at its Macondo well that triggered the largest U.S. offshore oil spill.

Drilling was shut down for months as regulators reviewed safety practices. The U.S. bolstered its oversight of the offshore industry after Macondo and added new protections for deep-water projects, such as setting up offshore containment systems in the event of a leaking oil well, said Lars Herbst, Gulf of Mexico regional director for the Bureau of Safety and Environmental Enforcement in New Orleans.

Drilling Pause
Companies used the pause to further their studies of the Lower Tertiary and fine-tune their drilling strategies, the University of Texas’ Snedden said.

“We’re seeing the benefits of that reinvestigation,” he said.

BP, after facing years of criticism for the spill that is set to cost it more than $40 billion, hasn’t recoiled from the Gulf. The London-based company still boasts the most licenses in the region and says it will have eight rigs drilling this year, more than ever before.

Petroleo Brasileiro SA, known as Petrobras, started production from its Cascade/Chinook wells in the Lower Tertiary last year. Chevron expects oil to start flowing next year at its Jack/St. Malo project.

The Jack and St. Malo fields are about 280 miles south of New Orleans and within 25 miles of each other. The company’s production platform for the project is built to handle the equivalent of as much as 177,000 barrels of oil a day.

Chevron remains among the most bullish companies on the Gulf of Mexico, with five rigs currently drilling there -- a record for the company.

Breakthrough Technology
“What catches our attention is the potential,” Ryan said, “billions of barrels right in our own backyard.” And it’s still in its infancy, he said. Chevron has identified some 45 drilling prospects in its inventory in the Lower Tertiary.

A key breakthrough has been new seismic tools that allow companies to see through layers of salt deposits that previously blocked their vision, opening up new parts of the formation to exploration. Conventional wisdom among geologists was that there would never be oil found beneath the salt -- a belief blown apart as wells such as Jack and St. Malo proved oil was hidden there, after all.

Costs remain high, at about $1 million a day to drill ultra-deep wells in deep water. Risks remain high too as companies remain in exploration mode. Cobalt International Energy Inc. announced a dry hole on Aug. 19 in the Lower Tertiary. Even as its stock dropped 15 percent that day, the company was undeterred, saying it would use the knowledge it gained from its dry hole to keep drilling.

Re-Exploration
The success rate in the Lower Tertiary so far has been about 60 percent, with 40 percent of discoveries having commercial potential -- a “tremendous” rate considering that 30 percent is considered good, Chevron’s Ryan said.

The value of the Lower Tertiary extends far beyond the Gulf of Mexico as companies tackle similar ultra-deep projects and formations off the coasts of Africa and Latin America. The engineering, seismic technology and basic experience obtained in the Gulf can be leveraged to lower costs and raise success rates in those regions.

The Gulf is the “tip of the spear” for that sort of learning,” Ryan said. The Lower Tertiary is a parable of re-exploration, showing how the future of the oil and gas industry depends on using new technology to re-discover already-explored regions.

When the 57-year-old executive started his career in the 1970s, 600 feet was considered “deep water.” Shale was useless rock. Oil didn’t exist below the salt layer.

“In the span of one person’s career -- just one person’s career -- two plays that couldn’t exist according to our professors and our mentors are now some of the biggest plays in the world,” he said.

“In the end, we need all of them.”




http://www.bloomberg.com/news/2013-...h-unlocks-1-5-trillion-oil-offshore-u-s-.html

 

[trysail]

http://www.lukoil.com/materials/gallery/116_1954_l.jpg


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